the ） the ） Luzhou Block is 10 - 25% higher than that in the Changning and Weiyuan blocks. 3 The deep shelf sedimentary center controls the distribution of high-quality shale in the Luzhou Block, and under the setting of low deep structure and abnormally high pressure, those well-developed high-angle natural fractures are good for the accumulation of free gas, and due to a high brittle material content there, the complex fracture networks are easily formed by fracturing, as a result, a high yield will be easily achieved for a shale gas well in this study area. In conclusion, high-yield and enrichment of shale gas reservoirs should be under such favorable conditions as being located in the deep-water shelf sedimentary center and with well-developed high-angle natural fractures under the setting of low steep structure and abnormally high pressure.

Yang, S., 2020. An analytical model for fluid imbibition in organic nanopores. Transport in Porous Media 131, 595- 615.

https://doi.org/10.1007/s11242-019-01358-z Estimating the fluid imbibition flow in natural system composed of nanopores is challenging due to the strong fluid/rock molecular scale interaction and the invalidation of the macroscopic thermodynamics treatment. We develop an analytical model for Lennard-Jones fluid imbibition into an organic nanopore considering the phase transition and fluid/rock intermolecular interactions. In addition, we apply the proposed model on octane molecules imbibition into 1 - 10 nm slit-shape graphite nanopores under the standard and shale reservoir condition. Predicted velocity and density profiles of 2 nm model at the standard condition show that octane molecules first imbibe as vapor phase at around 200 - 300 m/s and form adsorbed layers near the pore wall. Velocity and density profiles are compared with the molecular dynamic simulation results. Calculated mean 3 4 velocities of the analytical model and simulation are around 10 - 10 of those predicted by classical models, which are similar with previous experimental results. Reservoir condition results show octane can fast flow only when the driving pressure is greater than 0.12 MPa when the initial reservoir pressure is 5.72 MPa. Particularly, the impact of the fluid phase transition on the imbibition rate is significant in organic nanopores.

Yang, W., He, S., Iglauer, S., Guo, X., Zhai, G., Zhou, Z., Dong, T., Tao, Z., Wei, S., 2020. Porosity characteristics of different lithofacies in marine shale: A case study of Neoproterozoic Sinian Doushantuo formation in Yichang area, China. Journal of Petroleum Science and Engineering 187, 106856.

http://www.sciencedirect.com/science/article/pii/S0920410519312720 This study evaluates the pore network systems in the Neoproterozoic Sinian Doushantuo (Z1d) shale from the Yichang area in the Middle Yangtze region. All samples were classified based on their lithologies and examined by geochemical and petrographic analysis, assisted with carbon dioxide/nitrogen (CO2/N2) adsorption, mercury injection capillary pressure (MICP) and focused ion beam-scanning electron microscopy (FIB-SEM) to fully characterize the nanoscale porosity of the different shale lithofacies. The calcareous shale lithofacies group (I- C), mixed shale lithofacies group (II-M) and siliceous shale lithofacies group (III-S) were identified via ternary mineralogy diagrams. Clearly, different lithofacies had different porosities, pore volume, surface area and pore- size distribution (ranging from 0.3 nm to 36 μm). The mixed shale lithofacies group (II -M) had the highest total pore volumes, followed by the calcareous shale lithofacies group (I-C) and the siliceous shale lithofacies group (III-S). Peak values (2 - 20 nm, 20 - 50 nm, 50 - 60 nm and 90 - 200 nm) obtained from N2 adsorption were identified as organic matter (OM) pores, dissolution intraparticle (intraP) pores and intercrystalline pores (using SEM images analysis). Porosity shows a non-monotonic trend with TOC content and a maximum at 4.5 - 5.5 wt% TOC, similar relationships between TOC and mesopore/macropore volumes, due to pore collapse and compaction. The FIB-SEM images revealed solid bitumen and two types of kerogen in the examined shale samples; these different organic matter types had clearly distinct pore characteristics. While the smaller OM particles mobilized and converted into solid bitumen in which OMpores were larger and more abundant, the large-scale OMparticles were most likely non-porous inert maceral and sponge-like porous amorphous kerogen. Overall TOC content and organic types are the key controlling factors to the nanoscale porosity development in the Doushantuo Shale, and the Sinian Doushantuo shale (in the Yichang area) has great potential for shale gas exploration and exploitation in South China.